GASIFICATION PROCESS

Abstract

A process for the manufacture of a useful product from synthesis gas having a desired hydrogen to carbon monoxide molar ratio comprises gasifying a first carbonaceous feedstock comprising waste materials and/or biomass in a gasification zone to produce a first synthesis gas; optionally partially oxidising the first synthesis gas in a partial oxidation zone to generate oxidised synthesis gas; reforming a second carbonaceous feedstock to produce a second synthesis gas, the second synthesis gas having a different hydrogen to carbon ratio from that of the first raw synthesis gas; combining at least a portion of the first synthesis gas and at least a portion of the second synthesis gas in an amount to achieve the desired hydrogen to carbon molar ratio and to generate a combined synthesis gas and subjecting at least part of the combined synthesis gas to a conversion process effective to produce the useful product.

Claims

1. A process for the manufacture of a useful product from synthesis gas having a desired hydrogen to carbon monoxide molar ratio comprising: gasifying a first carbonaceous feedstock comprising waste materials and/or biomass in a gasification zone to produce a first synthesis gas; optionally partially oxidising the first synthesis gas in a partial oxidation zone to generate oxidised synthesis gas; reforming a second carbonaceous feedstock to produce a second synthesis gas, in which reforming the carbon monoxide content and the hydrogen content are both increased, the second synthesis gas having a different hydrogen to carbon monoxide ratio from that of the first synthesis gas; combining at least a portion of the first partially oxidised synthesis gas and at least a portion of the second synthesis gas in an amount to achieve the desired hydrogen to carbon monoxide molar ratio and to generate a combined synthesis gas; subjecting at least part of the combined synthesis gas to a conversion or separation process effective to produce the useful product.

2. The process according to claim 1 wherein the second synthesis gas has a higher hydrogen to carbon monoxide molar ratio than the first synthesis gas.

3. The process according to claim 1 wherein the reforming step is at least one of steam methane reforming and autothermal reforming.

4. The process according to claim 1 wherein at least a portion of one or more of the optionally partially oxidised first synthesis gas, the second synthesis gas and the combined synthesis gas is decontaminated in a clean-up zone.

5. The process according to claim 3 wherein the reforming step is in the presence of a catalyst, optionally wherein the catalyst is nickel-based.

6. The process according to claim 1 wherein the second carbonaceous feedstock is a gas.

7. The process according to claim 1 wherein the process is workable during downtime and/or interruption in the gasification zone.

8. The process according to claim 1 wherein the second carbonaceous feedstock comprises at least one of natural gas, renewable natural gas, biogas, low-carbon methanol and low carbon ethanol.

9. The process according to claim 1 wherein the first carbonaceous feedstock comprises at least one of woody biomass, municipal solid waste and commercial and/or industrial waste and/or agricultural residue.

10. The process according to claim 1 wherein the desired hydrogen to carbon molar ratio of the combined synthesis gas is from 1.5:1 to about 2.5:1, or preferably from about 1.7:1 to about 2.2:1, or more preferably from about 1.95:1 to about 2.05:1.

11. The process according to claim 1 wherein ammoniacal, sulphurous and carbon dioxide impurities are removed, preferably sequentially, in the clean-up zone.

12. The process according to claim 1 wherein sulphur is removed from the second carbonaceous feedstock prior to the reforming step.

13. The process according to claim 1 wherein CO.sub.2 is removed from the first synthesis gas prior to combination with the second synthesis gas, and/or from the combined synthesis gas.

14. The process according to claim 1 wherein the process does not include any water gas shift reaction.

15. The process according to claim 1 wherein the useful product is produced by subjecting at least part of the combined synthesis gas to a Fischer-Tropsch synthesis or ammonia synthesis or methanol synthesis.

16. The process according to claim 15 wherein the combined synthesis gas is converted by Fischer-Tropsch synthesis into liquid hydrocarbons.

17. The process according to claim 16 wherein the liquid hydrocarbons are upgraded into the useful product.

18. The process according to claim 17 wherein at least a part of the liquid hydrocarbons are upgraded by at least one of hydroprocessing, product fractionation, hydrocracking and/or isomerisation to produce the useful product.

19. The process according to claim 1 wherein the useful product comprises synthetic paraffinic kerosene and/or diesel and/or naphtha, optionally wherein the synthetic paraffinic kerosene and/or diesel and/or naphtha is combined with another fuel component to make a transportation fuel.

20. The process according to claim 19 wherein the biogenic content of the useful product is greater than the biogenic content of a useful product derived from the first carbonaceous feedstock only.

21. The process according to claim 1 wherein the first synthesis gas is subjected to partial oxidation and steam is generated by heat exchange with the gas heated in the partial oxidation zone.

22. The process according to claim 1 wherein the partially oxidised synthesis gas undergoes a simple quench after leaving the partial oxidation zone.

23. The process according to claim 1 wherein the first synthesis gas is subject to partial oxidation and carbon dioxide is recovered downstream of the partial oxidation zone.

24. The process according to claim 1 wherein the first synthesis gas is subjected to partial oxidation and natural gas, preferably renewal natural gas, is combusted in the partial oxidation zone.

25. The process according to claim 1 wherein the first synthesis gas is subjected to partial oxidation at a temperature of least about 1100° C., preferably at least about 1200° C., more preferably or at least about 1300° C., most preferably in the range of from about 1200° C. to about 1350° C.

26. A useful product produced by a process according to claim 1.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0223] Preferred embodiments of the invention are described below by way of example only with reference to FIGS. 1 and 2 of the accompanying drawings, wherein:

[0224] FIG. 1 is a simplified schematic diagram of a process for undertaking FT synthesis from a biomass and/or waste feedstock and renewable natural gas in accordance with a preferred embodiment of the invention; and

[0225] FIG. 2 is a simplified schematic diagram of a variant of the process of FIG. 1.

DETAILED DESCRIPTION

[0226] Referring to FIG. 1, a first carbonaceous feedstock is supplied in line 1 to Fuel Conditioning Facility (FCF) 2 and on in line 3 to gasification zone 4. Raw synthesis gas from gasification zone 4 is passed in line 5 to partial oxidation zone 6. Partially oxidised raw synthesis gas passes on in line 7 to gas clean-up zone 8, generating first clean synthesis gas in line 9.

[0227] A second carbonaceous feedstock is supplied in line 10 to reforming unit 11, which may be a steam-methane reformer or an autothermal reformer. Raw synthesis gas from reforming unit 11 is passed in line 12 to combine (line 13) with the clean synthesis gas from line 9. All or a portion of the combined synthesis gas in line 13 is fed to Fischer-Tropsch (FT) reactor train 14 and the resulting FT products are fed in line 15 to upgrading zone 16, generating a useful product stream in line 17.

[0228] Means are provided for controlling the amount of synthesis gas from reforming unit 11 that is combined with the waste derived synthesis gas from clean-up zone 8.

[0229] This embodiment involves the supplementing of waste-derived synthesis gas (which in the VLS scheme has a low H.sub.2:CO ratio of approximately 0.9) with hydrogen rich gas from a steam methane reformer (SMR) or autothermal reformer (ATR). Several different feedstocks could be considered for the reforming unit 11 with the most common being natural gas. Renewable Natural Gas (RNG) is the preferred feedstock.

[0230] Thus, the low H.sub.2:CO ratio syngas from waste gasification is combined with the high H.sub.2:CO ratio from the reforming unit 11 to produce a syngas that meets the H.sub.2:CO of approximately 2.00 requirement for Fischer-Tropsch synthesis.

[0231] It is possible to combine gasification and reforming unit-derived syngas streams to meet the H.sub.2:CO=2.00 specification without any separate water gas shift unit. If renewable natural gas (RNG) or natural gas (NG) supply is limited, it is possible that some water gas shift capacity is included in order to meet the FT requirements.

[0232] The syngas from the reforming unit 11 contains substantially lower concentrations of CO.sub.2 than the waste-derived syngas from line 9. Accordingly, it may be advantageous to remove CO.sub.2 from the latter. If there is economic incentive to capture and sequester the CO.sub.2, it may make sense to send the combined gasification and reformed syngas streams through a CO.sub.2 removal stage.

[0233] There are several Carbon Intensity (CI) benefits arising from this scheme including:

[0234] a) if Renewable Natural Gas (RNG) is used as the process feed 10 to the reforming unit 11, the biogenic content of the final fuels will increase relative to the biogenic content of a waste-derived product only;

[0235] b) if Renewable Natural Gas (RNG) is used as the process feed 10, the feedstock will be deemed to be renewable;

[0236] c) the power consumption per unit of produced reforming unit-derived syngas is considerably lower than that from a waste gasifier, reducing the power import requirements.

[0237] The reforming unit 11 can be fired with waste offgases from the facility and supplemented with pipeline Natural Gas (NG). Should it be difficult to meet the CI target (if, for example, the average CI of the UK grid did not decrease as rapidly as predicted) it is possible to fire the SMR unit with RNG and make up any deficit on the CI score.

[0238] Where RNG is used as the process feed to the reforming unit, the RNG feed relaxes the CI constraints and enables other cost saving modifications, such as simplification of the POx heat recovery scheme; and possible elimination of the entire internal power generation island.

[0239] The waste/NG co-fed plant of FIG. 1 would be expected to have a higher carbon and thermal efficiency than a plant that is fed only by waste.

[0240] The reforming unit 11 produces a wastewater (often referred to as “process condensate”) which can be readily upgraded to boiler feed water. The availability of this high-quality water can be used to offset the relatively high-water intake that it required to drive the gasification process.

[0241] Other advantages of the process scheme according to the present invention are as follows:

[0242] a) Early Facility Start-Up

[0243] It may be possible to start-up the reforming unit 11 earlier than the FCF-gasifier-POx-gas clean-up system. This will enable earlier production of final products, whilst the waste syngas production infrastructure is still under construction.

[0244] b) Faster Start-Up

[0245] The reforming unit 11 enables a faster route to FT liquid production following a trip. Once the reforming unit 11 and FT process 14 are online, the steam constraints are eased considerably too.

[0246] c) Availability

[0247] The reforming unit 11 is expected to have a considerably higher overall availability than the equivalent waste gasification train. As a result, one could reasonably expect a good increase in the overall plant availability. For example, in the case of expected and/or unexpected gasification interruption, the process according to the present invention will allow for sustained operation through either recycled tail gas to the reforming unit 11 to achieve the desired H.sub.2:CO ratio or once through operation of the FT unit. Both of these conditions can be achieved under dynamic operation conditions through feedback control loops or operator intervention. Additionally, operation of the reforming unit 11 (i.e. SMR or ATR unit) to produce H.sub.2 can be used to operate downstream product upgrading equipment without the gasifier online.

[0248] d) Syngas Quality

[0249] Major contaminants in the syngas from the reforming unit 11 are expected to be NH.sub.3 and to a much lesser extent, HCN. Sulphur is removed upstream of the reforming unit 11, as sulphur will poison the nickel reforming catalyst. By comparison, the waste-derived gas will contain a host of potential FT catalyst poisons. Introduction of the RNG derived gas is expected to dilute these waste-derived poisons and thereby reduce the risk of off-spec syngas to the FT process 14.

[0250] e) Steam Raising

[0251] If the facility is found to be short of steam, it is possible to consider “duct-firing” in the reforming unit 11 in order to raise additional saturated and/or superheated steam without having to install a standalone boiler.

[0252] Although this embodiment utilises RNG as the feedstock for the reforming unit 11, other carbonaceous materials can be fed into this reformer too including low carbon methanol, ethanol and higher hydrocarbons, providing the carbon intensity intention allows.

[0253] In a variant in which the reforming unit 11 is an oxygen-blown autothermal reformer (ATR), a synthesis gas with an H.sub.2:CO ratio of approximately 2.40 is generated in line 12. When the reforming unit 11 is an SMR unit, the SMR syngas has a ratio of approximately 4.50. Therefore, more ATR-derived syngas will be blended with the waste-derived syngas to meet the target H.sub.2: CO ratio of 2.00, when compared to SMR-derived syngas. This is expected to yield a higher biogenic content in the final product as well as a lower overall CAPEX and OPEX per barrel. The downside will be the considerable volume of RNG required to balance the facility.

[0254] In the embodiment of FIG. 2, the carbonaceous feedstock fed to the reforming unit, for example natural gas and/or renewable natural gas, is additionally supplied to the POx zone and thereby reduces the constraints on the plant.

[0255] Referring to FIG. 2, a first carbonaceous feedstock is supplied in line 1 to Fuel Conditioning Facility (FCF) 2 and on in line 3 to gasification zone 4. Raw synthesis gas from gasification zone 4 is passed in line 5 to partial oxidation zone 6. A second carbonaceous feedstock is supplied in line 18 to partial oxidation zone 6. Several different feedstocks could be considered for the second carbonaceous feedstock, with the most common being natural gas. Renewable Natural Gas (RNG) is the preferred feedstock. Partially oxidised raw synthesis gas passes on in line 7 to gas clean-up zone 8, generating first clean synthesis gas in line 9.

[0256] The second carbonaceous feedstock that is supplied to partial oxidation zone 6 is also supplied in line 10 to reforming unit 11, which may be a steam-methane reformer or an autothermal reformer. Raw synthesis gas from reforming unit 11 is passed in line 12 to combine (line 13) with the clean synthesis gas from line 9. All or a portion of the combined synthesis gas in line 13 is fed to Fischer-Tropsch (FT) reactor train 14 and the resulting FT products are fed in line 15 to upgrading zone 16, generating a useful product stream in line 17.

[0257] Means are provided for controlling the amount of synthesis gas from reforming unit 11 that is combined with the waste derived synthesis gas from clean-up zone 8.

[0258] Means are provided for controlling the amount of second carbonaceous feedstock that is fed to partial oxidation zone 6.